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March 18, 2025

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Calif. Officials Approve New Safety Measures for Battery Storage

The California Public Utilities Commission on March 13 voted to approve stricter safety standards on battery storage following a series of incidents at battery facilities. 

CPUC passed the new standards as an update to General Order 167, which became effective in 2005 and sets safety standards for electric generating facilities. The five-member commission voted unanimously to approve the update. 

The update provides “a method to implement and enforce maintenance and operation standards for electric generating facilities, in order to add new safety standards for the maintenance and operation of battery energy storage systems,” according to a news release.  

Additionally, the update requires battery storage facility owners to develop emergency plans in coordination with local authorities. It also imposes new technical logbook standards for battery storage systems, among other requirements. (See Calif. Officials Propose New Safety Measures for Battery Storage.) 

Commissioner John Reynolds said the resolution comes as battery storage grows rapidly in California. Battery storage capacity in the state grew from 500 MW in 2019 to over 13,000 MW in 2024, he noted. 

But the expansion of battery storage has caused safety concerns. The commissioners brought up the Jan. 16 fire at Vistra’s 300-MW energy storage facility at Moss Landing in Monterey County. The lithium-ion facility is one of the world’s largest battery energy storage systems. 

The fire, which prompted the evacuations of 1,200 people, is under investigation. Staff from CPUC’s Safety and Enforcement Division visited the site Jan. 22 as part of its probe.  

CPUC previously listed nine other safety incidents at facilities since 2021, including four in 2024. In one incident in September 2024, a fire at a San Diego Gas & Electric facility in Escondido prompted evacuations.  

Evacuations also were ordered in May 2024 during a fire at REV Renewables’ Gateway Energy Storage facility in Otay Mesa.  

“The broad effect of updating this general order is to extend existing safety standards for generation assets to grid scale energy storage systems, including grid scale batteries. This update will support the CPUC role in advancing battery safety and will help to keep Californians safe,” Reynolds said. 

CPUC also noted the importance of storage in California’s transition from fossil fuels.  

“Battery storage systems are one of the key technologies California relies on to enhance reliability and reduce dependency on polluting fossil fuel plants,” the news release stated. 

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NY Sells First Build-Ready Site for Renewables

A former iron mining operation once considered the largest of its type in the world has a new distinction: It will host the first site auctioned in New York’s Build-Ready program for large-scale renewables. 

The New York State Energy Research and Development Authority announced March 13 that CleanCapital had won rights to build and operate a 12-MW solar array in Benson Mines in the Adirondack Mountains region. 

Build-Ready is designed to address multiple state policy goals, including renewable energy development and brownfield reuse. 

NYSERDA assesses the viability of sites suggested for the program, then works with the landowners to design a customized benefits package and to advance the design, permitting and interconnection processes, then offers it as ready to construct. Ideally, this offers prospective developers a much-simplified path compared with starting from scratch on their own. 

The pre-auction process still can be lengthy, however. The Benson Mines project was announced in April 2021 with a planned early 2024 auction date, for example. And it initially was envisioned as a 20-MW project but was scaled back to avoid the need for system upgrades. 

NYSERDA said it has screened more than 5,000 sites and moved only a handful into more-advanced stages of potential development. Just three other sites besides Benson Mines are listed as having reached Build-Ready status: a former landfill, the grounds of an airport and an unused city property. 

Benson Mines began mining in the 1800s. It was a powerhouse for the region’s economy in its day, ranking as the world’s largest open pit iron mine by 1950. But it closed in 1978, leaving one more cluster of crumbling industrial structures in a region where tourists and seasonal residents far outnumber industrial workers. 

The former mine has been cleared of the rusting relics. Benson Mines now runs a 1,500-acre timber operation there, and sells aggregate crushed from the estimated 60 million tons of rock on site. 

The solar array will be placed on a tailings pile and is a good fit for the long-term goals for the site, company President Stuart Carlisle said in a news release: “This project has allowed us to put an underutilized portion of the Benson property back into productive use, bringing new investment, infrastructure development and economic benefits to the local community.” 

It will be one of the largest photovoltaic projects in the Adirondack Park, which with its highly regulated land use and rugged wilderness terrain does not lend itself to massive solar arrays. 

In a telling bit of geography, the state’s forest ranger training academy is held just down the road. 

But more importantly, a National Grid substation is even closer. 

NYSERDA President Doreen Harris said as the first of its kind, the Benson Mines project has value beyond its 12 MW of carbon-free power generation capacity: “We have now completed our first auction and are supporting the transformation of this underutilized site into something that is, in fact, build-ready. The Build-Ready program is helping to reimagine sites across the state so that communities can benefit from these otherwise-abandoned spaces.” 

CleanCapital will finance, construct, own and operate the project and has entered into a 20-year Renewable Energy Certificate agreement with NYSERDA. 

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ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes

ISO-NE provided stakeholders with a high-level overview of its proposed prompt capacity market design and discussed several other aspects of its capacity auction reform (CAR) project at a two-day meeting of the NEPOOL Markets Committee on March 11 and 12.

The CAR project aims to transform the region’s Forward Capacity Market, with auctions held over three years prior to each yearlong capacity commitment period (CCP), into a prompt and seasonal capacity market, held a month or two prior to each CCP, which would be split into summer and winter periods with separately procured capacity. (See ISO-NE Refines Scope, Schedule for Capacity Auction Reforms.)

Chris Geissler, director of economic analysis at ISO-NE, said the RTO would run the first prompt auction in April or May 2028 for the CCP beginning on June 1, 2028. It would finalize resources’ qualified capacity values in early 2028.

New resources would need to be in service prior to the auction to sell capacity, Geissler said. One of the motivations behind the prompt auction format is to eliminate “phantom entry,” in which an in-development resource secures a capacity supply obligation (CSO) but does not come online in time for the CCP.

Geissler said ISO-NE would provide “as much opportunity for new resources to demonstrate being in service as possible.” The RTO would allow non-commercial resources to participate in auction qualification and intends to set the latest possible deadline for resources to demonstrate they have achieved commercial operation.

He emphasized that the fundamentals of the demand curve and bid formulation will stay the same in a prompt market.

“Under either a forward or a prompt auction, a resource’s competitive capacity offer price should consider the incremental costs associated with taking on a CSO,” Geissler said.

He noted that some costs that would be included in offers in a forward auction — such as investment costs for a new resource — could not be included in offers in a prompt market. While this could lower some offer prices, Geissler said he does not expect this to lower overall market prices.

“Resources that are considering investment costs will only incur those costs if they expect to recover them via the markets, whether those markets are forward or prompt,” Geissler said. “We would therefore expect similar quantities of capacity to be sold in a forward or prompt market, producing comparable capacity prices.”

Seasonal Market Update

Jennifer Engelson, supervisor of resource qualification at ISO-NE, provided additional information on the RTO’s plans for the seasonal divide of the CCP.

ISO-NE would split the annual CCP into six-month summer and winter seasons beginning and ending at the ends of April and October, respectively. These periods would be aligned with the seasons used in NYISO’s capacity market. ISO-NE would run separate seasonal auctions for the next CCP each spring.

Dividing the CCP into two seasons is intended to help ISO-NE mitigate growing winter reliability risks, driven by heating electrification and gas supply issues. While ISO-NE considered using more than two seasons, it determined that “two longer seasons with clear peaks would be more economically efficient for the region” because of the concentration of risks in the winter and summer, Engelson said.

Resource Deactivations

Under ISO-NE’s existing tariff, the resource retirement process is tied to the FCM, and resources planning to retire signal their intent about four years prior to their exit from the market.

Because a prompt auction would provide little time to address potential system issues caused by the retirement, ISO-NE plans to decouple the retirement process from the capacity market. (See NEPOOL Markets Committee Briefs: Feb. 11, 2025 and ISO-NE Introduces Proposed Resource Retirement Changes.)

Under the new process, deactivation notices would be due two years prior to each CCP. Notices would be binding and set off a review process to evaluate potential reliability and market power issues created by the resource’s retirement.

The reliability review — triggered for all resources with more than 20 MW of capacity — would include an evaluation of local transmission security. If issues are identified, ISO-NE could retain the resource through an out-of-market agreement. The RTO has said repeatedly it plans to consider resource retentions only to address local transmission security issues and will not retain resources for energy security.

To evaluate and mitigate market power, the ISO-NE Internal Market Monitor would review deactivation submissions “to determine whether the retirement is justified by economics or potentially motivated by benefits to a portfolio.”

Retiring resources would be subject to a conduct test to evaluate the economics of the retirement and a net portfolio benefits (NPB) test to assess whether retiring a profitable resource would increase revenue for the resource owner’s remaining portfolio.

“When a participant fails both the conduct and the NPB test, this suggests that the deactivation represents an exercise of market power,” said Zeky Murra-Anton, an economist at ISO-NE.

When market power is identified, ISO-NE plans to impose a 1.5-times multiplier on the projected increase in portfolio-wide revenue caused by the retirement. Murra-Anton said this multiplier is intended “to effectively deter deactivations for market power purposes without being excessively punitive.”

Treatment of Repowering Resources

ISO-NE also discussed how the CAR changes would affect resource repowering efforts.

The RTO’s interconnection procedures and FCM have mechanisms for evaluating changes to existing resources. Both the interconnection process and the FCM are undergoing major reform efforts, which will necessitate changes to the treatment of resource repowering.

Alex Rost, director of transmission services at ISO-NE, assured stakeholders that the RTO is committed to retaining “a path for repowering projects as the CAR design is set.”

“At a fundamental level, [interconnection customers] with repowering projects that seek to change/replace an original generating facility with a new generating facility, where the new generating facility assumes its needed interconnection service from the original generating facility, will maintain the ability to do so,” Rost wrote in a memo issued prior to the meeting.

NEPGA Tie Benefits Concerns

Bruce Anderson, general counsel for the New England Power Generators Association, presented some concerns about how ISO-NE’s capacity market accounts for tie benefits, which the RTO has defined as “the assumed amount of emergency assistance from neighboring control areas that New England could rely on … in the event of a capacity shortage.”

“The current market design ‘assumes away’ approximately 2,000 MW of capacity demand based on the belief that system energy from neighboring control areas is equivalent to ‘firm capacity,’” Anderson said, adding that these assumed tie benefits reduce the region’s installed capacity requirement.

Because tie benefits are not subject to the same obligations, audits and nonperformance charges as resources with CSOs, Anderson said treating tie benefits as “equal to actual capacity” creates risks of price suppression and capacity under-procurement.

Anderson added that price suppression increases the likelihood of “uneconomic retirements of resources important to system reliability.”

He said NEPGA will propose alternatives intended to improve ISO-NE’s tie benefits accounting methodology in the coming months.

Flexible Response Services

Also at the meeting, Matthew White, vice president of market development and settlements at ISO-NE, discussed the RTO’s long-term plan to improve its flexible response capabilities “to address greater operational uncertainties with an increasingly weather-dependent resource mix.”

In a memo issued prior to the meeting, White wrote that ISO-NE is “assessing a combination of new probabilistic forecasts and enhancements to the co-optimized energy and reserve markets.”

On March 1, ISO-NE launched a new day-ahead ancillary services market, which procures reserves to help grid operators cope with load variability and fill any energy gaps that arise between the day-ahead energy market and the load forecast. (See FERC Approves ISO-NE’s Day-Ahead Ancillary Services Initiative.)

Looking forward, ISO-NE is considering how to improve its real-time forecasting of ramping needs and may look to procure “dynamically determined incremental quantities” of 10- and 30-minute reserves and new longer-response reserve products, potentially in the 60- or 90-minute range, White said.

“New England’s power system is becoming increasingly dynamic, and extending conceptually familiar market designs with new probabilistic modeling capabilities appears to be a promising next step to reliably address increasing operational uncertainties,” White wrote.

“By carrying less incremental reserves when net load uncertainty or ramping needs are forecast to be low, unnecessary costs can be avoided; and by increasing incremental reserves when net load uncertainty or ramping needs are forecast to be higher, reliability can be maintained,” he added.

Fall Markets Report

Finally, the IMM’s Kathryn Lynch presented the Monitor’s fall quarterly markets report, which found that wholesale market costs during the quarter increased by 8% relative to fall 2023, up to nearly $1.5 billion in total costs.

Market costs increased despite a 13% decrease in natural gas prices and the lowest recorded fall season power demand.

The increase was driven by increased emissions costs for the Regional Greenhouse Gas Initiative and decreased imports and domestic nuclear generation, Lynch said. Average hourly nuclear generation decreased by about 423 MW compared to the prior fall “due to planned and forced outages,” while net imports dropped by an hourly average of 892 MW because of “dry weather in Québec and a nuclear generator outage in New Brunswick.”

Overall, market pricing outcomes were competitive, and “there was no evidence of impactful capacity withholding,” Lynch said.

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Ahead of Crossover Day, Energy Bills Stalled in Md. General Assembly

State energy policy was supposed to be a top priority for the Maryland General Assembly’s 2025 session, but it appears to be taking a backseat to more pressing fiscal matters.  

With lawmakers in Annapolis mostly focused on producing a budget that can fill the state’s projected $3 billion deficit, many energy bills appear stalled in advance of “crossover day” on March 17, when bills introduced in one house must be approved in that chamber and cross over to the other.  

Dozens of energy bills have been introduced in both houses, but few have taken the first step of being approved by their appropriate committees, let alone moved to a floor vote. 

The budget is taking up a lot of time and “mental space,” said Kim Coble, executive director of the Maryland League of Conservation Voters. But the bigger issue is the complexity of the energy issues addressed by the bills state delegates and senators are considering. 

“There’s a lot of need to educate members and to bring them along, and the number of bills and topics that are trying to be addressed [is] major,” Coble said. “They are getting lots of phone calls from constituents about their electricity bills; they’re getting lots of calls about clean energy and trying to balance it all.  

“So, I am trying to stay optimistic,” she said. “The fact that things haven’t moved yet is not a delay tactic. It’s because it is a tough, complicated topic that they want to get right.” 

Both Coble and Katie Mettle, policy principal for Maryland at Advanced Energy United, also note that any bills not crossing over by March 17 still can move forward in the legislature via a special vote in the Rules Committee in either house. 

“I think they honestly just are not sweating the crossover deadline for their top, most important bills, because they know they can take longer if they want to,” Mettle said. “They just want to make sure that everything is to their liking. … There [are] still negotiations going on.” 

Coble pointed to the Abundant, Affordable Clean Energy (AACE) Act (HB 398, SB 316), sponsored by Del. Lorig Charkoudian (D) and Sen. Benjamin Brooks (D). The bill’s multiple provisions include a mandate for the Maryland Public Service Commission to open two rounds of applications each for 150 MW of distribution-tied energy storage and 1,600 MW of front-of-the-meter, transmission-tied storage, as well as incentives for 3,000 MW each of utility- and small-scale solar projects.  

The bill also seeks to support the state’s existing nuclear plants via license extensions and zero-emission credits, and calls for coordinated planning for transmission to bring offshore wind energy to the homes and business that need it. It requires prevailing wage standards for workers employed on energy storage projects. 

The goal, Charkoudian said is “to ensure resource adequacy, with protecting ratepayers and with clean energy.” 

As of March 13, the bill was sitting in committees in both houses, but both Coble and Charkoudian said negotiations are underway to incorporate parts of AACE into another major bill, the Next Generation Energy Act, which is one of three major energy bills being supported by House and Senate leadership. 

The Leadership Package

Referred to as “the leadership package,” the three bills include: 

    • The Energy Resource Adequacy and Planning Act (SB 909), which would require the PSC to establish an Integrated Resource Planning Office, which would conduct a 25-year comprehensive energy forecast aimed at meeting state clean energy and emission reduction goals, while ensuring reliability and affordability. 
    • The Renewable Energy Certainty Act (SB 931), which would set rigorous standards for solar and storage projects seeking a certificate of public necessity and convenience from the PSC, to ensure careful siting and community engagement. The bill also would prohibit city or county governments from passing zoning or other laws blocking solar and storage projects. 
    • The Next Generation Energy Act (SB 937), which would promote the development of nuclear energy, and the extension of the licenses of existing reactors, as a matter of state policy, while also encouraging regional collaboration between states to share costs on the development of new reactors. The bill also calls for the procurement of 3,100 MW of “dispatchable energy generation capacity” and a temporary expedited permitting process for these projects. 

Advocates like Mettle have raised red flags about those 3,100 MW of dispatchable generation, which she presumes would be natural gas. “The thing about gas [is] we just don’t need it,” she said. “I just don’t think from a technological standpoint or an economic standpoint that it’s remotely necessary.” 

Mettle would first like to see PJM clear the solar and storage projects sitting in its interconnection queue and then ensure the state is ready to support projects as they are approved for interconnection. She supports SB 931 and the AACE Act as ways to “turbocharge” the solar and storage industry.  

Both Charkoudian and Coble are concerned any expedited permitting will strip out requirements for community engagement and attention to environmental justice issues. 

Charkoudian is working on amendments that will incorporate parts of AACE into SB 937. “So, I think what you’re going to see, when they kind of come out or start going through the process in committee, is just a lot of amendments to add, to improve, take the best ideas and move them on,” she said. “I think it’s possible that that won’t happen before crossover.” 

Crossovers So Far

The Maryland Clean Energy Center tracks energy and climate bills in the General Assembly and issues weekly reports. As of March 13, the following bills have crossed over: 

    • SB 37, another Charkoudian bill, would require utilities to report to the PSC on their votes at all PJM stakeholder and other meetings. Its House counterpart, HB 121, still is in committee. 
    • HB 270 calls for a state-level data center impact analysis report to be developed by the Department of the Environment, the Maryland Energy Administration and the University of Maryland School of Business, and to be submitted to the governor and General Assembly by Sept. 1, 2026. 
    • SB 120 and HB 4, approved in both houses, prohibits community or condo associations from putting restrictions on solar installations that would increase the cost of the projects by 5% or reduce their electrical output by 10%. 
    • HB 61 would require the design for any new school construction or major renovation to evaluate installing solar parking canopies.  
    • SB 399 would allow transmission lines to be run through certain state-designated “wildlands.”  

Maryland LCV is opposing the bill, which Coble said is tailored to the Mid-Atlantic Resiliency Link, which is being developed by NextEra Energy. Wildlands are particularly pristine areas and account for less than 1% of the state’s land, she said. 

“This would be the first time the state of Maryland has ever opened up wildlands from new transmission lines. So that, in and of itself, is bad,” she said. “These wildlands are pretty special lands, and they do need and deserve extra consideration.” 

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EPE’s Markets+ Decision ‘Not Transparent,’ NM Regulators Say

A New Mexico Public Regulation Commission workshop March 13 aimed to restore trust between the commission and El Paso Electric after the utility’s surprise announcement in January that it planned to join SPP’s Markets+.

The PRC held a series of workshops last year to explore issues related to two competing day-ahead markets in the West: Markets+ and CAISO’s Extended Day-Ahead Market.

During a workshop in August, El Paso Electric representatives said they hoped to conduct further studies comparing benefits of the two markets. They indicated they’d present results of the new studies to the commission before choosing a market, a decision they expected to make in the third quarter of 2025, according to Commissioner Gabriel Aguilera.

When EPE announced its choice of Markets+ on Jan. 24, many were taken by surprise — including the New Mexico commissioners. (See El Paso Electric to Join SPP’s Markets+ in 2028.)

“The last thing I wanted was a surprise filing or announcement by a utility that they’re joining ‘X’ market,” said Aguilera, who has been leading the workshops. “EPE’s announcement surprised me. And it surprised a lot of people.”

“It was not transparent,” Aguilera added. “And I really hope to bring transparency back into this by having this workshop.”

Commission Chair Pat O’Connell said the workshop was important to “reset” the relationship between the PRC and El Paso Electric.

“When you say you’re going to do something, you’ve created the expectation. And then when you don’t do it, it breaks the trust,” O’Connell said.

Emmanuel Villalobos, EPE’s director for market development and resource strategy, said the utility had “misrepresented ourselves” in saying the new study results would be shared before making a market announcement.

“We are deeply sorry for that miscommunication,” Villalobos said.

In addition to hosting the series of workshops last year, the PRC issued a set of “guiding principles” in late October intended to help utilities make a day-ahead market choice. (See NM PRC Issues ‘Guiding Principles’ for Electricity Market Participation.)

Brattle Group Study

During the workshop, Brattle Group principal John Tsoukalis presented results of a recent study completed for El Paso Electric, which looked at benefits of day-ahead market participation if EPE joined Markets+ and Public Service Company of New Mexico (PNM) joined EDAM.

PNM announced its choice of EDAM in November. (See PNM Picks CAISO’s EDAM.)

The new study was a follow-up to Brattle’s previous study that projected annual benefits for EPE of $19.1 million a year if both New Mexico utilities joined EDAM, versus $9.1 million if they joined Markets+. (See Brattle New Mexico Study Shows EDAM Benefits Outpacing Markets+.)

The updated study projected annual benefits of $6.6 million for EPE if the utility joins Markets+ but PNM goes with EDAM.

But Brattle’s figures changed when the consultant incorporated estimates of the value of the Eddy County tie, a 345-kV transmission line that connects EPE with the Eastern Interconnection. With the Eddy County tie value factored in, EPE’s annual benefits would be $19.3 million if both New Mexico utilities join EDAM, $20.1 million if they join Markets+, and $18.8 million if EPE goes with Markets+ while PNM joins EDAM, Brattle projected.

With the new study showing a smaller difference in monetary benefits among the different market scenarios, EPE weighed other factors in its market decision, including governance, reliability and resource adequacy. And Markets+ seemed to be a better fit.

“Market participation must be viewed holistically, considering both financial and operational realities,” EPE said in a presentation.

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Data Centers’ Need for Speed Clashing with Plodding Pace of Regulation

WASHINGTON — Even if demand forecasts from new data centers are twice as large as what ends up being built, the growth is going to be at a scale where the power industry’s regulations need to change to keep up with it, former FERC Commissioner Allison Clements said at the Energy Bar Association’s Northeast Chapter Winter Summit on March 12. 

“You have a desire for AI dominance, and then you still have this slow-churning, difficult regulatory process to get through,” said Clements, who since leaving FERC has started working part time at ASG, which helps build data centers. 

The power industry is among the most regulated in the country, and anytime a decision has to be made or money spent, it has to go through at least couple of proceedings, she added. The exuberance around data center expansion and artificial intelligence’s potential is starting to clash with that. 

“The reality is, whether or not Stargate is actually going to deploy $500 billion in the U.S. depends on all those regulatory check marks,” Clements said. “Nobody has stood up in this moment of exuberance and said, ‘I’m going to spend the money no matter what. That money is still going to go through each individual company and investment community, right? You’re still going to have to check all these boxes.” 

In the next few years, as Orders 2023 and 1920 are only being implemented; new natural gas turbines are taking five years to get installed; and clean, firm power supply options are not commercially viable, the industry is going need to get creative to serve new large loads, Clements said. 

“This isn’t a technological problem; it’s a political will, operational kind of structural/institutional issue,” Clements said. 

The existing grid can have its capacity maximized with new software and hardware; interconnections could be optimized across seams; and the industry could look to the new large customers themselves to help, she added. 

FERC Chair Mark Christie is split by the issue, with Clements saying he understands the concerns about holding other customers harmless from the infrastructure expansions required by large data centers but he also sees the other side. “He’s very clear about the political pressure and the market pressure to get something done, to unlock the jam.” 

Co-location has dominated the issue at FERC so far, with Christie saying he wants a proposed rulemaking, issued at February’s open meeting, to be finished quickly. (See FERC Launches Rulemaking on Thorny Issues Involving Data Center Co-Location.) 

The nuclear plants in PJM initially were paid for by ratepayers, and many wound up being subsidized to keep running by their states as cheap shale gas ate into their profits, but Clements noted they often are in fully restructured states. 

“Now those resources have found better commercial opportunities,” Clements said. “The way the market, if it was a fully functioning market, should work is that we facilitate those opportunities.” 

Co-located load can either be served entirely by its unit or get backup from the grid, said Jennifer Mansh, Talen Energy senior vice president of regulatory affairs. While the concept has been pursued around PJM and in other markets, so far Talen’s Susquehanna nuclear plant in Pennsylvania is the only one to have a co-located data center. 

FERC rejected an expansion of that co-located data center when it launched a broader look at the issue, and Talen is challenging the rejection in court, she added. The industry should get more clarity as PJM and other parties respond to the rulemaking and its dozens of questions in the next week, Mansh said. 

“There’s an acknowledgement that we need to move urgently, but then you see so many questions about the detail of how this might work,” said Carrie Allen, deputy general counsel for Constellation Energy, referring to FERC’s co-location proceeding. “And I would just suggest to the commission, if I had a chance to talk to all of them, that not every single one of those 39 questions needs to be addressed … in order to figure out the broader contours of a policy framework.” 

FERC says it wants to move quickly on the issue, but so far that has not been the case, said Nicholas Gladd, partner at Wilson Sonsini Goodrich & Rosati. “I also think what’s on their minds, based on that lengthy list of questions, is they want to do something big and great because they think this is a big problem,” he added. 

But not all of those questions need to be answered immediately, he said. Gladd would prefer to let the market work and bring its own solutions to the fore, rather than have too many top-down regulations around co-location. PJM is facing some resource adequacy issues, but throttling down large loads does not get to the markets’ root problems, in addition to being bad for national security, he said. 

“Given the capacity market has those flaws, and the interconnection queue has those flaws, the fact that there’s new large growth is an opportunity, not a risk,” Gladd said. “What better investment signal, or what better factor to indicate that an investor signal is robust, than hundreds of megawatts of load?” 

After years of flat load growth in most of the country that came with many traditional, thermal generators retiring and replaced by intermittent renewables, the growth in data centers has exposed some underlying tensions on the grid, said Mike Twomey, senior consultant for Charles River Associates. 

“This increased demand for electric service by data centers in many parts of the country is causing a lot of friction on issues that have been largely, I guess the right word is … ‘underground’ for the last 20 years,” Twomey said. 

Some parts of the grid might even be incapable of serving massive new load unless they bring supply along with the new demand, he added. Many of the data center developers want to be supplied by clean energy, but if they need it, they will not hesitate to supply a facility with natural gas generation, Twomey said. 

While some data centers can shop around for the best places to plug into the grid, that will not be possible in every case because of issues around latency, said Michael Armm, managing director of BlackChamber Group. Latency refers to the lag that happens when data is sent across long distances, which requires proximity for some applications. 

The need for latency has kept the sector growing in Data Center Alley in Virginia and nearby. Latency will be an even bigger issue as autonomous vehicles move beyond the pilot project stage. 

“Thinking about autonomous vehicles, if you’re at an intersection and there’s four cars and one’s going to start moving, the other one is going to react to it; you can’t wait for that signal to go 500 miles away to a data center to … go through an algorithm and [be] sent to the car next to you,” Armm said. “That timing is much faster, so you’re going to see more edge computing.” 

Autonomous vehicles could require smaller, distributed data centers sprinkled around cities that can handle a few blocks worth of traffic, he added. 

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FERC Approves New York Transco’s Formula Rate, Sets ROE for Hearing

FERC on March 11 approved including additional expense accounts in New York Transco’s new company-wide formula rate over the protests of the New York Public Service Commission and New York City, but set its proposed return on equity for hearing and settlement procedures (ER25-885).

Transco was formed by Consolidated Edison, Avangrid, National Grid and Central Hudson Gas & Electric in 2014 in response to a state solicitation for transmission projects in case the Indian Point nuclear plant retired (which it did in 2021). The company’s rate formula and ROE for those Transmission Owner Transmission Solutions (TOTS) projects were approved, but it has had to submit project-specific cost recoveries for each new project since then.

The company proposed a new formula rate across all of its projects and a company-wide ROE of 10.9%. Included in the rate were expense accounts under FERC’s Uniform System of Accounts related to general transmission operations and maintenance, including interconnection service studies.

Transco said these expenses were already included in its project-specific rates but under a different account for third-party vendors. It argued “that its significant growth suggests that it may be more efficient and cost effective if [it] were to open its own control center and utilize its own employees to perform these and other tasks.” Other NYISO transmission owners have the accounts as part of their approved formula rates, it contended.

The PSC argued that the rate change had not been vetted enough to ensure it would not raise rates for consumers. New York City and Multiple Intervenors, a group of industrial consumers, jointly claimed that Transco was improperly booking the expenses in the third-party vendor account, allowing the company to improperly collect transmission operating expenses via its formula rate.

FERC dismissed these arguments. In response to the PSC, FERC noted that Transco was not seeking to raise its rates through the new accounts, but to change the accounts under which certain expenses are booked. “We find no evidence in this record to conclude that this change will necessarily lead to cost increases,” it said.

The commission also said that the city and Multiple Intervenors’ concerns were beyond the scope of the proceeding. “Challenges to costs included in the formula rate may be raised in the annual update process in accordance with New York Transco’s formula rate protocols,” it said.

FERC found that Transco’s proposed base ROE was not demonstrably just and reasonable and set the matter for hearing and settlement judge procedures.

The company said the new ROE would apply to its existing transmission assets, including TOTS, and any future projects it develops and owns. This excludes the Propel NY Energy project, in development with the New York Power Authority, because its cost recovery is the subject of a separate settlement agreement.

Transco submitted testimony from an expert witness, which determined the zone of reasonableness to be 9.08 to 12.72%, resulting in a 10.9% midpoint. For comparison, Transco’s ROE for TOTS is 9.65%.

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Dragos Outlines Voltzite Electric Utility Breach

The first known intrusion into a U.S. electric utility’s computer network by the Voltzite hacker group was significantly mitigated by its proactive approach to cybersecurity, security firm Dragos said in a case study March 12. 

Voltzite is the name given by Dragos to a threat group identified in its most recent Year in Review report that demonstrates “extensive technical overlaps with” the China-connected Volt Typhoon group, which has been accused of embedding itself in U.S. critical infrastructure organizations’ information technology networks for at least five years.  

The group has displayed the ability to reach Stage 2 of SANS Institute’s ICS kill chain, meaning “a capability that can meaningfully attack” the target’s industrial control systems. (See Dragos: Attacks on ICS Increased in 2024.) 

Dragos’ case study describes Littleton Electric Light and Water’s (LELWD) discovery of the hacker group in its system in 2023 and its efforts to root them out. LELWD is a public utility providing electricity to Littleton and Boxborough, Mass. 

The utility initially learned its network had been breached when the FBI called the utility’s assistant general manager on a Friday afternoon to warn him of a possible compromise. The following Monday, FBI agents and representatives from the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) arrived to investigate the breach. 

Fortunately for LELWD, the utility already was working to improve its cybersecurity stance. With the help of a grant from the American Public Power Association, LELWD had contracted with Dragos to “gain visibility of its [operational technology] assets, secure IT-OT network traffic, and monitor communications between OT devices and systems. The firm also was contracted to provide threat hunting services. 

With the warning of the compromise, LELWD accelerated its deployment of the Dragos products. The company’s platform identified specific behaviors confirming Voltzite’s presence, which allowed the utility to “eradicate the adversary and secure the network against additional threats.” 

Dragos said its partnership with LELWD “demonstrates the value of specialized OT security solutions for critical infrastructure providers of all sizes” and “has positioned LELWD to better protect its operations and serve its communities securely in an evolving threat landscape.” 

Dragos’ report comes at a time of rising concern about the federal government’s willingness and ability to support utilities during a cybersecurity crisis. CISA, which assisted LELWD with the Voltzite intrusion, has been without a director since former Director Jen Easterly resigned at the beginning of the second Trump administration, and DHS Secretary Kristi Noem criticized the agency at her confirmation hearing for its efforts to address foreign disinformation campaigns. (See CISA Leader Reiterates China Cyber Warnings.) 

Noem called for a “smaller [and] more nimble” CISA focused on threats to critical infrastructure. Since she took over, CISA has put some employees focused on dis- and misinformation on administrative leave. Media reports have suggested the staff reductions at the agency went further, with a former penetration tester at CISA alleging in a LinkedIn post that two “red teams” that tested government networks for cyber vulnerabilities had been laid off. 

However, CISA pushed back on these claims March 12 in its first press release since Jan. 21, saying the red teams have not been laid off, but that the agency “has taken action to terminate contracts where the agency has been able to find efficiencies and eliminate duplication of effort.” CISA said the action “did not impact the employment status of CISA personnel” and the red teams “continue their work without interruption.” 

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Pathways Initiative Receives Praise, Skepticism at Calif. Hearing

California state senators on March 12 heard arguments for and against the bill to implement “Step 2” of the West-Wide Governance Pathways Initiative, with some lawmakers voicing concerns about guardrails against market manipulation and what the effort means for the Golden State’s autonomy to set its own energy policies. 

Members of the state Senate Energy, Utilities and Communications Committee brought in proponents and opponents of the Pathways Initiative for an informational hearing. Pathways is an effort to support expansion of CAISO’s Western Energy Imbalance Market (WEIM) and the soon-to-be-implemented Extended Day-Ahead Market (EDAM) to entities outside California by shifting governance of the markets from the ISO to a proposed independent regional organization (RO). 

Sen. Jerry McNerney (D) said he was “a little nervous” about the risks associated with establishing a day-ahead market intended to unleash the value of the market. He cited Enron, which collapsed spectacularly after its market manipulation schemes wreaked havoc on California and CAISO during the electricity crisis of 2000/01. 

“I mean, what are the risks here? I mean, have you laid those risks out so that we can get a clear understanding what they might look like?” McNerney said. 

Siva Gunda, vice chair at the California Energy Commission, responded that the effort is about optimizing existing resources and ensuring “we have access to the largest number of resources.” 

Gunda also noted that California has put in place several guardrails since the Enron crisis, including market monitoring at CAISO and statutory responsibility to protect the public interest. 

Sen. Monique Limón (D) said she is “slightly more skeptical” of where she will land on the issue, “in part because what I’m looking for are what those guardrails would be like.” 

Limón said she would need more details on guardrails as they evolve and how those will be designed to keep up with new technology “that poses a risk to a lot of our systems, not just this.” 

Members of the committee also asked questions about how the initiative would impact California’s independence over its energy policies and how it differs from previous attempts to expand energy markets in the West. 

Alice Reynolds, president of the California Public Utilities Commission, said previous efforts focused on expanding CAISO’s balancing authority area, noting the ISO would remain a BAA within its current boundaries under the Pathways proposal. (See California Energy Officials Pitch Pathways Plan to State Senators.) 

Participation in the market is voluntary, Reynolds said, adding, “We would keep the control of our operation, of our transmission in the CAISO. She pointed out that “we would just be making a decision about whether the CAISO should join a market, or regional market, and then CAISO itself would operate it.” 

‘Incredibly Difficult Environment’

Democratic Sens. Henry Stern and Josh Becker introduced SB 540 — or the Pathways bill — in February. The proposed legislation sets conditions under which CAISO and Golden State utilities can participate in energy markets governed by an independent RO. (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.) 

During the March 12 hearing, Stern said he appreciated the scrutiny about how the effort will impact California’s autonomy and emissions goals.  

However, Pathways can help build trust among Western states amid trade wars with Canada, staff cuts at the Bonneville Power Administration and other actions taken by the Trump administration aimed toward the energy sector, according to Stern. 

“There’s a lot of politicization in the energy arena, too,” Stern said. He added “the reason, I guess, I’m a part of this initiative is that I think we still have to be on that mission and try to … build that trust in an incredibly difficult environment.” 

He said it is a tricky balancing act to ensure the economic and reliability benefits will work for states like California, which is “as green as it gets, or for a state that doesn’t want to make that their banner.” 

The commission heard from various other stakeholders, including environmental organizations, labor parties and utilities. 

Michael Colvin, director of regulatory and legislative affairs at the Environmental Defense Fund, told the commission, “To ensure that we have a fully clean electric grid funded by affordable bills, and that we make the necessary clean infrastructure investments to keep the lights on, we must leverage the geographic diversity of the West.” 

“I think of Pathways as a critical ingredient to help us fight climate change, to ensure that our electric bills remain affordable and that we have the reliability that we need to keep the lights on,” Colvin added. 

Skeptics of Pathways also joined the meeting, including former CPUC President Loretta Lynch. 

Lynch contended that many of the arguments favoring Pathways rely on hypothetical scenarios in which EDAM would consist of participants from all Western states. This is unlikely, Lynch said, noting several entities already have decided not to join EDAM. 

Lynch also said California would give up control of energy policies and risk losing jobs to other Western states. 

Right now, California is in charge, “but Pathways throws all that out. California gets a yet to be priced seat in the back of the plane where don’t know the destination, how the plane is flown, or even our ticket price, until and unless you give up control of the pilot seat,” Lynch said. 

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MISO Intent on Answers as to IMM Role in Tx Planning

NEW ORLEANS — MISO confirmed it’s taking steps to get answers from FERC about the role the Independent Market Monitor should have — if any — in transmission planning.

During March Board Week, MISO Director Trip Doggett said the board was put in a tough position, with some members agreeing the IMM should monitor transmission expansion from an independent perspective and others vehemently opposed to the Monitor critiquing MISO’s planning in addition to market operations.

MISO board members on Feb. 14 ultimately passed a motion directing MISO to ask FERC whether it’s appropriate for the IMM to analyze the value of proposed transmission. In the meantime, MISO is to freeze any funding for independent scrutiny of transmission planning by the IMM until MISO gets clarity. (See Board Orders MISO to Get Answers on IMM’s Role in Tx Planning.)

The board drew up the motion following IMM David Patton’s vocal opposition to MISO’s nearly $22 billion long-range transmission portfolio over 2024.

“We felt like being responsible for the budget, we really couldn’t let the IMM continue until we have clarification,” Doggett explained at the March 11 Markets Committee of the MISO Board of Directors.

During a March 12 Advisory Committee meeting, MISO counsel Jacob Krause said MISO would pose the question to FERC sometime in the second quarter. MISO may file a petition for a declaratory order with FERC; the RTO has not confirmed that’s the route it will take.

Attorney Ken Stark, representing MISO’s end-use customers, said he found MISO’s intent to file problematic. Some state regulatory staff also have expressed concern over the appearance of MISO effectively shutting the IMM out of planning discussions for the time being.

During a March 13 MISO board meeting, Organization of MISO States President and Minnesota Public Utilities Commissioner Joseph Sullivan said a few regulators have strong opinions about MISO temporarily withholding funding. He said OMS is following developments closely.

“We have agreed to disagree on that topic,” MISO Board Chair Todd Raba said, though he added MISO was working with FERC and the IMM to draft a filing.

Patton did not comment on the future filing over the course of Board Week, though in the past he’s said repeatedly that markets and transmission planning cannot be viewed in isolation because of their interdependence.

At a Feb. 25 OMS board meeting, Wisconsin Public Service Commissioner Marcus Hawkins said it was “surprising how the process played out,” with MISO leading the charge to stop payments to the IMM on transmission planning assessments. He pointed out that states and MISO are free to disagree with the Monitor’s independent views.

“[It] seems ironic that the only time that MISO has ever brought this up is when the IMM disagrees with its transmission planning,” said Bill Booth, consultant to the Mississippi Public Service Commission. He questioned whether MISO was trying to “silence” its IMM.